1. Field of the Invention
This invention relates to a method and apparatus for separation of gaseous components in a gas mixture. In one aspect, this invention relates to membranes for gas separation. In another aspect, this invention relates to the separation of CO2 from CO2-containing gas mixtures such as power plant flue gas.
2. Description of Related Art
Amine gas treating refers to a group of processes that use aqueous solutions of alkylamines, also referred to simply as amines, to remove hydrogen sulfide (H2S) and carbon dioxide (CO2) from gaseous mixtures. A variety of amines are used for gas treating, the most common of which are monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA), diisopropylamine (DIPA), and diglycolamine (DGA). A typical amine gas treating process and system includes an absorber and a regenerator as well as accessory equipment. A gas stream containing H2S and/or CO2 and an amine solution are introduced into the absorber, wherein the H2S and/or CO2 is absorbed into the solution, producing a gas stream free of H2S and/or CO2 and an amine solution rich in the absorbed acid gases. The acid gas rich amine solution is then introduced into a regenerator wherein the acid gases are separated, i.e. stripped, from the amine solution, producing an amine solution which can then be recycled for reuse in the absorber and stripped gases containing concentrated H2S and/or CO2.
Amine absorption is currently the U.S. Department of Energy (DOE)/National Energy Technology Laboratory (NETL) and industry benchmark technology for the capture of CO2 from power plant flue gas. Systems analysis studies have estimated that using chemical absorption with an aqueous monoethanolamine system to capture 90% of the CO2 from flue gas will require an increase in the cost of energy services of about 75-85%. Such an increase in the cost of energy is well above the 2020 DOE/NETL Sequestration Program post-combustion capture goal of 90% capture in existing plants with less than a 35% increase in the cost of energy. Thus, it is important that new advanced CO2 capture technologies be developed in order to maintain the cost-effectiveness of U.S. coal-fired power generation.
One such technology involves the use of membranes. Compared with amine absorption, membrane processes require less energy to operate and do not require chemicals or regenerating absorbents to maintain. In addition, membranes are compact and can be retrofitted onto the tail end of power-plant flue gas streams without complicated integration. Recent systems analysis and feasibility studies show that membranes are a technically feasible and economically viable option for CO2 capture from the flue gas exhaust from coal-fired power generation. The two basic criteria for determining whether a membrane can be effectively utilized for flue gas applications are permeance and selectivity in the desired operating environment.
One recent study has shown that the optimal membrane CO2/N2 selectivity for separation of CO2 from flue gas is in the range of about 20 to 40. Increasing selectivity further has almost no effect on the cost of CO2 capture. Rather the critical factor for reducing CO2 capture cost is increasing membrane permeance. For example, when CO2/N2 selectivity is greater than 30, an increase in CO2 permeance from 1000 to 4000 gas permeation units (GPU) causes a decrease in CO2 capture cost by nearly 50%.
Currently, the only commercially viable membranes for CO2 removal are polymer based, such as polysiloxanes, cellulose acetate, polyimides, polyamides, polysulfone, polycarbonates, and polyetherimide. The most widely used and tested of these membrane materials is cellulose acetate. However, these commercially available polymer membranes for CO2 removal typically have a permeance of only about 100 GPU, which is too low for flue gas CO2 capture, and a CO2/N2 selectivity of about 30. Thus, there is a need for new membranes for flue gas CO2 capture.
One such membrane is the POLARIS™ membrane of Membrane Technology and Research, Inc., which has a CO2 permeance of about 2,000 GPU and a CO2/N2 selectivity of about 50. Another such membrane, currently under development, is a gelled ionic liquid membrane to achieve a CO2 permeance of 10,000 GPU and a CO2/N2 selectivity of at least 20. Still another such membrane is a mixed matrix membrane having a CO2 permeable layer comprising a continuous phase of polymeric material and inorganic particles uniformly dispersed throughout the continuous polymeric phase. Although such mixed matrix membranes have not been commercialized for gas separation, similar mixed matrix membranes have been commercialized for seawater desalination.